This invention relates generally to the field of perforating and stimulating subterranean formations to increase the production of oil and gas therefrom. More specifically, the invention provides a new and improved perforating gun assembly for use in multiple-stage stimulation operations using a diversion agent, such as ball sealers.
Naturally occurring deposits of oil and gas are typically produced using wells drilled from the earth""s surface. A wellbore penetrating a subterranean formation typically consists of a metal pipe (casing) cemented into the original drill hole. Lateral holes (perforations) are shot through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical (often acid) stimulation may be used to increase the flow capacity. Hydraulic fracturing consists of injecting viscous fluids into the formation through the perforations at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical, fracture or fracture network. Granular proppant material, such as sand, ceramic beads, or other materials, is generally injected with the later portion of the fracturing fluid to hold the fracture(s) open after the pump pressures are released. Increased flow capacity from the reservoir results from the high permeability flow path left between the grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatments, economic and technical gains are realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including the use of ball sealers. The primary advantages of ball sealer diversion are low cost and low risk of mechanical problems. Costs are low because the process can typically be completed in one continuous operation, usually during just a few hours. Only the ball sealers are left in the wellbore to either flow out with produced hydrocarbons or drop to the bottom of the well in an area known as the rat (or junk) hole. The primary disadvantage is the inability to be certain that only one set of perforations in the desired interval will fracture at a time so that the correct number of ball sealers are dropped at the end of each treatment stage. Obtaining optimal benefits from the process depends on one fracture treatment stage entering the formation through only one perforation set and all other open perforations remaining substantially unaffected during that stage of treatment. Further disadvantages are lack of certainty that all of the perforated intervals will be treated and of the order in which these intervals are treated while the job is in progress. In some instances, it may not be possible to control the treatment so that individual zones are treated with single treatment stages.
One multi-stage treatment method which employs the use of ball sealers is the xe2x80x9cJust-in-Time Perforatingxe2x80x9d (xe2x80x9cJITPxe2x80x9d) method disclosed in co-pending patent application Ser. No. 09/891,673 filed Jun. 25, 2001. The JITP stimulation method is a method for individually treating each of multiple intervals within a wellbore while maintaining the economic benefits of multi-stage treatment: it provides a method for designing the treatment of multiple perforated intervals so that only one such interval is treated during each treatment stage while at the same time determining the sequence in which intervals are treated. One of the primary benefits of the JITP method is that it allows more efficient chemical and/or fracture stimulation of many zones, leading to higher well productivity and higher hydrocarbon recovery (or higher injectivity) than would otherwise have been achieved.
More specifically, the method involves perforating, treating, and isolating a given zone, and continuously and sequentially performing the same process for a number of zones up the well. The JITP process proceeds generally as follows: A select-fire perforating gun assembly, consisting of multiple gun sections containing shaped charges, is sent downhole via wireline to the first zone of interest. Each gun section can be individually fired via electric signal transmitted by the wireline. The first gun section is fired to form perforations in the well casing at the first zone. The gun assembly is then immediately pulled up hole to the next zone to be treated. The first stage of treatment is pumped into the wellbore and forced to enter the first set of perforations. Ball sealers are pumped down the well with the later portion of the treatment and ultimately seat on the perforations, thus isolating the first zone. The second gun section is then fired to create perforations at the second zone, and the gun assembly is pulled up hole to the next zone to be treated. The second stage of treatment is pumped while maintaining a high pressure in the wellbore, thus ensuring that the ball sealers on the previous set of perforations remain seated and that the treatment is diverted to the current perforated zone. The process is repeated for each zone to be treated.
There are several potential problems which could arise during the JITP stimulation process that could either limit the number of zones treated during a given trip downhole or affect the quality of the individual treatments. For example, the perforations may have burrs (sharp pieces of well casing metal extruding from the perforations into the wellbore) that form as a result of the firing process of shaped charges. These burrs can be non-uniform or very large about the perforation circumference, and as a result the ball sealers may not properly seat on the perforations. Treatment fluid may then leak past the ball sealers, which could result in that zone being over-treated and thus failure to optimally divert the treatment fluid to the current zone of interest, which in turn could lead to sub-optimal production out of one or more zones.
Depending on the distance between the outer wall of the gun section housing and the well casing, known as the xe2x80x9cshot clearancexe2x80x9d, and the positioning of the shaped charges about the circumference of the gun assembly, known as the xe2x80x9cshot phasing,xe2x80x9d the diameter of the perforations made may be variable. Typically, the greater the shot clearance, the smaller the diameter of the perforation made by the shaped charge. If the gun assembly drifts or is forced to one side of the wellbore, and the shot phasing is such that shaped charges are aimed at various locations about the wellbore circumference, the resulting perforations may have a significant variation in diameter and ovality; the larger perforations will be more likely to take the treatment fluid since they will have less frictional pressure losses. The size and shape of the perforations can also affect the seating of the ball sealers, where excessively large and small perforations or oval-shaped perforations may not allow the balls to seat and seal optimally. It may also compromise their mechanical integrity.
During each treatment stage of the JITP process, the ball sealers must travel downhole past the gun assembly to reach their destination. If the gun assembly has an outer diameter relative to the well casing inner diameter such that the annular area between the gun assembly and the inner wall of the well casing is small, then the ball sealers may have difficulty getting past the gun assembly. As a result the ball sealers may get lodged in part of the assembly or between the gun assembly and the well casing. Even if the gun assembly has a moderately sized outer diameter but is centralized in the well casing, the ball sealers may become lodged between the gun assembly and the casing or within the components of the gun assembly. The treatment may be compromised if even one of the ball sealers fails to make it past the perforating assembly or is temporarily hindered from reaching the targeted perforation of the treated zone.
Since the JITP process involves over-balanced perforating (i.e., maintaining high pressure in the wellbore while perforating), opening up a new set of perforations can cause a large pressure differential between the wellbore and the formation. This pressure imbalance can cause the gun assembly to get sucked against the perforations before it can be pulled up hole to the next interval. This sticking force may be so great that the wireline may not be sufficiently strong to overcome the frictional force between the gun assembly and well casing. The only way to unstick the gun may be to lower the wellbore pressure. However, this may cause the ball sealers on the previously completed zones to unseat, reducing the diversion effectiveness and possibly causing the treatment to be terminated.
The various embodiments of the inventive perforating gun assembly and the various novel components described below serve to address one or more of these problems described above.
The various embodiments of the apparatus of the present invention are for use in perforating multiple intervals of at least one subterranean formation intersected by a cased wellbore and in treating the multiple intervals using a diversion agent, such as ball sealers. In one embodiment, the apparatus of the present invention comprises a perforating assembly having a plurality of select-fire perforating devices interconnected by connector subs, with each of the perforating devices having multiple perforating charges. The apparatus also includes at least one decentralizer, attached to at least one of the perforating devices, which is adapted to eccentrically position the perforating assembly within the cased wellbore so as to create sufficient ball sealer clearance between the perforating assembly and the inner wall of the cased wellbore to permit passage of at least one ball sealer. The apparatus may also include one or all of the following components: (i) at least one stand-off adapted to create an imposed shot clearance between the perforating assembly and the inner wall of the cased wellbore when the perforating assembly is eccentrically positioned, (ii) means for creating burr-free perforations in the cased wellbore upon firing of the perforating charges, (iii) a depth locator for monitoring the depth of the perforating assembly, and (iv) a bridge plug and corresponding bridge plug setting tool for isolating previously completed intervals of the formation.
In another embodiment, the apparatus comprises at least one select-fire perforating device having multiple perforating charges and at least one decentralizer adapted to eccentrically position the perforating device within the cased wellbore so as to create sufficient ball sealer clearance between the perforating device and the inner wall of the cased wellbore to permit passage of at least one ball sealer. The apparatus may also include one or more of the components listed above.
In other embodiments, the apparatus of the present invention is used in perforating multiple intervals of at least one subterranean formation intersected by a cased wellbore and in treating the multiple intervals using a diversion agent such as sand, ceramic materials, proppant, salt, polymers, waxes, resins, viscosified fluids, foams, gelled fluids or chemically formulated fluids. In one embodiment, the apparatus comprises a perforating assembly comprising a plurality of select-fire perforating devices interconnected by connector subs, with each of the perforating devices having multiple perforating charges. The apparatus also includes at least one decentralizer, attached to at least one of the perforating devices, which is adapted to eccentrically position the perforating assembly within the cased wellbore. The perforating assembly is eccentrically positioned so as to create sufficient diversion agent clearance between the perforating assembly and the inner wall of the cased wellbore to (i) permit passage of a diversion agent with reduced frictional losses when the diversion agent flows past the perforating assembly and (ii) to treat at least one of the multiple intervals following perforation of the interval. This embodiment may also include one or more of the other components listed above.